Betaines for Shale Stabilization

ABSTRACT

Included are methods and systems for drilling in a subterranean formation. A method comprises providing a drilling fluid comprising an aqueous base fluid and a betaine shale stabilizer; placing the drilling fluid into the subterranean formation; and drilling a wellbore in the subterranean formation. A drilling system comprises a drilling fluid comprising an aqueous base fluid and a betaine shale stabilizer; a drilling assembly; a drill string coupled to the drilling assembly; a pumping system fluidically coupled to the drill string, wherein the pumping system is capable of pumping the drilling fluid through the drill string.

BACKGROUND

Provided are compositions and methods for water-based drilling fluids.More particularly, compositions and methods are provided for water-baseddrilling fluids comprising a betaine shale stabilizer.

During the drilling of a wellbore into a subterranean formation, adrilling fluid, also referred to as a drilling mud, may be continuouslycirculated from the surface down to the bottom of the wellbore beingdrilled and back to the surface again. Among other functions, thedrilling fluid may serve to transport wellbore cuttings up to thesurface, cool the drill bit, and provide hydrostatic pressure on thewalls of the drilled wellbore. Drilling fluids may be used in shaleformations comprising water-swellable shales, which may also be referredto as water-swellable clays. As the water-swellable shales are exposedto water, they may swell and consequently increase wellbore pressure. Onthe extreme end, an increase in wellbore pressure may create a dangerouswellbore condition which could result in an explosion. Lesser increasesin wellbore pressure may cause formation damage or may increase thedrilling fluid viscosity to a point where further drilling becomesdifficult.

To stabilize the water-swellable shales a variety of shale stabilizersmay be added to the drilling fluid. Examples of shale stabilizersinclude short chain amines, polymeric amines (e.g., polyacrylamide), andquaternary ammonium ions. However, these shale stabilizers may be toxicat the concentrations necessary for shale stabilization, thus posing arisk to personnel and the environment. Further, the shale stabilizersmay not be biodegradable and/or biocompatible. Thus, the shalestabilizers may pollute the environment, formation, water table, etc.,which may lead to increased cleanup costs. Further, many of theaforementioned shale stabilizers are expensive and their cost may limitthe types of wells that may be drilled and may also reduce overallprofitability of the operation.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some examples of thepresent invention, and should not be used to limit or define theinvention.

FIG. 1 is a schematic diagram of an example drilling assembly.

DETAILED DESCRIPTION

Provided are compositions and methods for water-based drilling fluids.More particularly, compositions and methods are provided for water-baseddrilling fluids comprising a betaine shale stabilizer.

In examples, the disclosed drilling fluids may be water-based drillingfluids. The drilling fluids may be used in the drilling of subterraneanformations, and may be particularly beneficial in the drilling ofsubterranean formations comprising water-swellable shales. The drillingfluids may comprise a betaine shale stabilizer as a drilling fluidadditive. The betaine shale stabilizer may be non-toxic. The betaineshale stabilizer may be biodegradable. The betaine shale stabilizer maybe biocompatible. The drilling fluids may comprise reduced shalestabilizer loading relative to other water-based drilling fluidscomprising non-betaine shale stabilizers. In examples where the drillingfluids are used in operations to drill through subterranean formationscomprising water-swellable shales, the betaine shale stabilizer mayreduce the amount of swelling present in the water-swellable shalesrelative to drilling fluids that do not comprise betaine shalestabilizers. As a result, the amount of wellbore pressure during thedrilling operation may be reduced relative to comparable drillingoperations using drilling fluids that do not comprise betaine shalestabilizers. In optional examples, the drilling fluids may compriseother drilling fluid additives such as weighting agents.

As stated above, the drilling fluids comprise a betaine shalestabilizer. A betaine is a specific species of zwitterion comprising aneutral chemical compound with a positively charged cationic functionalgroup which bears no hydrogen atom (e.g., a quaternary ammonium,phosphonium cation, etc.) and a negatively charged functional group(e.g., a carboxylate group) which may or may not be adjacent to thecationic site. Examples of betaines may include alkyl betaines, forexample glycine betaine; branched betaines; betaine derivatives, forexample, sulfobetaine and phosphobetaine; amine-functionalized betaines;the like, or a combination thereof. In some examples, the betaines maycomprise short-chain betaines defined as betaines comprising a carbonnumber fewer than 10. In some examples, a single species of betaineshale stabilizer may be included in a drilling fluid. In alternativeexamples, multiple species of betaine shale stabilizers may be includedin a drilling fluid. The betaine shale stabilizer may be present in thedrilling fluids at a concentration in a range of about 0.1 pound perbarrel (“lb/bbl”) to about 10 lb/bbl. Where a barrel is 42 US gallons.For example, a betaine shale stabilizer may be present in a drillingfluid in a concentration of about 0.1 lb/bbl to 10 lb/bbl. 0.1 lb/bbl,about 0.5 lb/bbl, about 1 lb/bbl, about 2 lb/bbl, about 5 lb/bbl, about7 lb/bbl, about 9 lb/bbl, or about 10 lb/bbl.

Without limitation by theory, a betaine shale stabilizer may inhibit, atleast partially, the potentially swellability of water-swellable shaleswhen these water-swellable shales are contacted by an aqueous-baseddrilling fluid comprising the betaine shale stabilizer. This effect maybe due to the betaine shale stabilizer forming a barrier on the surfaceof the water-swellable shale which may prevent access to thewater-swellable clay by water and may also selective interact with waterto prevent the water from further interaction with the water-swellableshale. For example, the positively charged cationic functional group ofthe betaine may interact with the negatively charged surface of thewater-swellable shale, thus blocking interaction between water and thatspecific site of the negatively charged surface of the water-swellableshale. Further, because water possesses a permanent dipole moment, thisinteraction may leave the negatively charged functional group of thebetaine to potentially interact with the slight positive charge of thehydrogen atoms of a water molecule, which may prevent the interaction ofthe water with the negatively charged surface of the water-swellableshale. Therefore only the slight negative charge of the oxygen atom inthe water molecule would be left free, and said slightly negativecharged oxygen would be repelled from the negatively charged surface ofthe water-swellable shale. In examples comprising short-chain betainescomprising a carbon number fewer than 10, the betaines may be lesslikely to foam the drilling fluid and thus may reduce the need fordefoamer or other techniques used to mitigate foam formation in thedrilling fluid. In some embodiments, the drilling fluids may benon-foamed and as such may be provided such that foaming is not inducedby mixing or by the addition of the betaine shale stabilizer or by anyother component which may induce foaming. In some embodiments where foamis generated, the foam may be removed by the addition of defoamer orthrough any other component or technique used to remove foam in adrilling fluid.

In examples, the betaine shale stabilizer may be non-toxic at theconcentrations used in the disclosed drilling fluids. Non-toxic isdefined herein as a product that does not produce immediate personalinjury or illness to humans when it is inhaled, swallowed, or absorbedthrough the skin. As such, the betaine shale stabilizer may be preparedfor use in the disclosed drilling fluids with a reduced risk topersonnel as compared to the use of toxic non-betaine shale stabilizers.The betaine shale stabilizer may be biodegradable at the concentrationsused in the disclosed drilling fluids. Biodegradable is defined hereinas any material which is capable of degradation by a microorganism orthrough any other biological means. The betaine shale stabilizer maybiodegrade at varying rates dependent upon the species of betaine shalestabilizer chosen and the conditions present to induce biodegradation.Thus, the betaine shale stabilizer may be used during drillingoperations and may be placed and/or disposed on the surface or within asubterranean formation, without a reduced risk of forming a permanentdeposit of the betaine shale stabilizer on the surface or within thesubterranean formation. The betaine shale stabilizer may bebiocompatible at the concentrations used in the disclosed drillingfluids. Biocompatible is defined herein as the ability to be in contactwith a living system (e.g., plants, animals, etc.) without producing anadverse effect. The betaine shale stabilizer may contact living systemswithout risk of damaging those systems and may therefore be used inoperations and/or at concentrations in which other shale stabilizers maynot be used. For example, the betaine shale stabilizer may be used inoperations where the risk of and the potential damage caused bypollution may be elevated.

The drilling fluids may comprise an aqueous base fluid. The aqueous basefluid may be from any source provided that it does not contain an excessof compounds that may undesirably affect other components in thedrilling fluids. For example, a drilling fluid may comprise fresh wateror salt water. Salt water generally may include one or more dissolvedsalts therein and may be saturated or unsaturated as desired for aparticular application. Seawater or brines may be suitable for use insome examples. Further, the aqueous base fluid may be present in anamount sufficient to form a pumpable slurry. In certain examples, theaqueous base fluid may be present in the drilling fluids in an amount inthe range of from about 33% to about 100% by weight of the drillingfluids. In certain examples, the aqueous base fluid may be present inthe drilling fluids in an amount in the range of from about 35% to about70% by weight of the drilling fluids. One of ordinary skill in the artwith the benefit of this disclosure will recognize the appropriateamount of aqueous base fluid for a chosen application.

The drilling fluids may additionally comprise drilling fluid additives.The drilling fluid additives may include, but are not limited toviscosifiers, non-betaine shale stabilizers, weighting agents,lost-circulation materials, pH buffers, thixotropic additives, defoamingagents, etc. In some examples, the drilling fluids may be substantiallyfree of solids. Alternatively, in some examples, the drilling fluid maycomprise solids. The solids may be any type of solids found in awellbore or introduced into a wellbore fluid. Without limitation,examples of solids may include pieces of the formation, drill cuttings,and additives introduced to a drilling fluid, e.g., lost circulationmaterials, weighting agents, etc.

The drilling fluids may optionally include a viscosifier. Theviscosifier may include, but is not limited to a substituted orunsubstituted polysaccharide; a substituted or unsubstitutedpolyalkenylene, wherein the substituted or unsubstituted polysaccharideor polyalkenylene is crosslinked or uncrosslinked; a polymer includingat least one monomer selected from the group consisting of ethyleneglycol, acrylamide, vinyl acetate, 2-acrylamidomethylpropane sulfonicacid or its salts, trimethylammoniumethyl acrylate halide, andtrimethylammoniumethyl methacrylate halide; a crosslinked orcrosslinkable gel; a poly(vinyl alcohol) homopolymer; poly(vinylalcohol) copolymer; a crosslinked poly(vinyl alcohol) homopolymer;crosslinked poly(vinyl alcohol) copolymer; any other suitableviscosifier; and/or any combinations thereof. If present, theviscosifier is included in the drilling fluids in a concentrationsufficient to achieve the desired result for a chosen application. Withthe benefit of this disclosure, one of ordinary skill in the art will beable to determine if a viscosifier is necessary, to choose anappropriate viscosifier, and to determine the appropriate concentrationof the viscosifier used.

Weighting agents may be included in the drilling fluids. Weightingagents are typically materials that weigh more than water and may beused to increase the density of drilling fluids. By way of example,weighting agents may have a specific gravity of about 2 or higher (e.g.,about 2, about 4, etc.). Examples of weighting agents that may be usedinclude, but are not limited to, hematite, illmenite, hausmannite,barite, and combinations thereof. Specific examples of suitableweighting agents include HI-DENSE® weighting agent, available fromHalliburton Energy Services, Inc. If present, the weighting agents areincluded in the drilling fluids in a concentration sufficient to achievethe desired result for a chosen application. With the benefit of thisdisclosure, one of ordinary skill in the art will be able to determineif a weighting agent is necessary, to choose an appropriate weightingagent, and to determine the appropriate concentration of the weightingagent used.

Lost-circulation materials may be included in the drilling fluids to,for example, help prevent the loss of fluid circulation into thesubterranean formation. Examples of lost-circulation materials includebut are not limited to, cedar bark, shredded cane stalks, mineral fiber,mica flakes, cellophane, calcium carbonate, ground rubber, polymericmaterials, pieces of plastic, grounded marble, wood, nut hulls, plasticlaminates (Formica® laminate), corncobs, and cotton hulls. If present,the lost-circulation materials are included in the drilling fluids in aconcentration sufficient to achieve the desired result for a chosenapplication. With the benefit of this disclosure, one of ordinary skillin the art will be able to determine if a lost-circulation material isnecessary, to choose an appropriate lost-circulation material, and todetermine the appropriate concentration of any lost-circulationmaterials used.

The drilling fluids may optionally comprise a pH buffer. Any pH buffermay be used to maintain the pH of the drilling fluids within a suitablerange, for example, about 8 to about 10.5. Examples of pH buffers mayinclude, but should not be limited to carbonates, bicarbonates,phosphates, hydroxides, and the like. If present, the pH buffer isincluded in the drilling fluids in a concentration sufficient to achievethe desired result for a chosen application. With the benefit of thisdisclosure, one of ordinary skill in the art will be able to determineif a pH buffer is necessary, to choose an appropriate pH buffer, and todetermine the appropriate concentration of any pH buffer used.

Thixotropic additives may be included in the drilling fluids to, forexample, provide a drilling fluid that may be a thin or low viscosityfluid when pumped or exposed to shear, however, if allowed to remainquiescent the drilling fluid may attain a relatively high viscosity.Among other things, thixotropic additives may be used to help controlfree water, create rapid gelation in the drilling fluids, combat lostcirculation, prevent “fallback” in annular column, and minimize gasmigration. Examples of suitable thixotropic additives include, but arenot limited to gypsum, water soluble carboxyalkyl, hydroxyalkyl, mixedcarboxyalkyl hydroxyalkyl either of cellulose, polyvalent metal salts,zirconium oxychloride with hydroxyethyl cellulose, or a combinationthereof If present, the thixotropic additives are included in thedrilling fluids in a concentration sufficient to achieve the desiredresult for a chosen application. With the benefit of this disclosure,one of ordinary skill in the art will be able to determine if athixotropic additive is necessary, to choose an appropriate thixotropicadditive, and to determine the appropriate concentration of anythixotropic additive used.

Optionally, defoaming additives may be included in the drilling fluidsto, for example, reduce the tendency of the drilling fluids to foamduring mixing and/or transfer. Examples of suitable defoaming additivesinclude, but are not limited to, polyol silicone compounds. Suitabledefoaming additives are available from Halliburton Energy Services,Inc., under the product name D-AIR™ defoamers. If present, the defoamingadditives are included in the drilling fluids in a concentrationsufficient to achieve the desired result for a chosen application. Withthe benefit of this disclosure, one of ordinary skill in the art will beable to determine if a defoaming additive is necessary, to choose anappropriate defoaming additive, and to determine the appropriateconcentration of any defoaming additive used.

The drilling fluids may be substantially free or free of added clays.“Added” clays are defined herein as clays added to the drilling fluidsprior to introduction of the drilling fluids in a subterraneanformation. Examples of added clays may include, but are not limited tomontmorillonite, kaolite, or hectorite. In some examples, the drillingfluids may consist essentially of the betaine shale stabilizer and anaqueous base fluid. One of ordinary skill in the art with the benefit ofthis disclosure will recognize whether the drilling fluids should befree of or substantially free of added clays.

The drilling fluids may comprise a density sufficient for drillingthrough a target subterranean formation. The density of the drillingfluids may be altered by the addition of drilling fluid additives (e.g.,weighting agents) as disclosed above. The correct density to use for adrilling operation may be determined by a variety of factors, one ofwhich may include the subterranean formation pressure. The density ofthe drilling fluids may be any density in a range of 8 pounds per gallon(“ppg”) to 20ppg. For example, the density of the drilling fluids may be8 ppg, 10 ppg, 12 ppg, 15 ppg, 18 ppg, or 20 ppg.

A method for drilling in a subterranean formation is disclosed. Themethod may comprise providing a drilling fluid comprising an aqueousbase fluid and a betaine shale stabilizer; placing the drilling fluidinto the subterranean formation; and drilling a wellbore in thesubterranean formation. The drilling fluid may comprise the betaineshale stabilizer in an amount in a range of about 0.5 lb/bbl to about 10lb/bbl. The drilling fluid may comprise the betaine shale stabilizer inan amount in a range of about 2 lb/bbl to about 7 lb/bbl. The betaineshale stabilizer may be selected from the group consisting of alkylbetaines, amine functionalized betaines, branched betaines, betainederivatives, and any combination thereof. The betaine shale stabilizermay be glycine betaine HCl. The aqueous base fluid may be present in thedrilling fluid in an amount in the range of from about 33% to about 100%by weight of the drilling fluid. The subterranean formation may comprisea water-swellable shale. The drilling fluid may not be foamed. Thebetaine shale stabilizer may possess one property selected from thegroup consisting of non-toxic, biodegradable, biocompatible, andcombinations thereof.

A method for drilling in a subterranean formation is disclosed. Themethod may comprise preparing a drilling fluid comprising an aqueousbase fluid and a betaine shale stabilizer; circulating the drillingfluid into the subterranean formation, wherein the subterraneanformation comprises a water-swellable shale; drilling a wellbore in thesubterranean formation while circulating the drilling fluid; andcontacting the water-swellable shale with the drilling fluid. Thedrilling fluid may comprise the betaine shale stabilizer in an amount ina range of about 0.5 lb/bbl to about 10 lb/bbl. The drilling fluid maycomprise the betaine shale stabilizer in an amount in a range of about 2lb/bbl to about 7 lb/bbl. The betaine shale stabilizer may be selectedfrom the group consisting of alkyl betaines, amine functionalizedbetaines, branched betaines, betaine derivatives, and any combinationthereof The betaine shale stabilizer may be glycine betaine HCl. Theaqueous base fluid may be present in the drilling fluid in an amount inthe range of from about 33% to about 100% by weight of the drillingfluid. The subterranean formation may comprise a water-swellable shale.The drilling fluid may not be foamed. The betaine shale stabilizer maypossess one property selected from the group consisting of non-toxic,biodegradable, biocompatible, and combinations thereof.

A drilling system is disclosed. The drilling system may comprise adrilling fluid. The drilling fluid may comprise an aqueous base fluidand a betaine shale stabilizer. The drilling system may further comprisea drilling assembly; a drill string coupled to the drilling assembly;and a pumping system fluidically coupled to the drill string, whereinthe pumping system is capable of pumping the drilling fluid through thedrill string. The drilling fluid may comprise the betaine shalestabilizer in an amount in a range of about 0.5 lb/bbl to about 10lb/bbl. The drilling fluid may comprise the betaine shale stabilizer inan amount in a range of about 2 lb/bbl to about 7 lb/bbl. The betaineshale stabilizer may be selected from the group consisting of alkylbetaines, amine functionalized betaines, branched betaines, betainederivatives, and any combination thereof The betaine shale stabilizermay be glycine betaine HCl. The aqueous base fluid may be present in thedrilling fluid in an amount in the range of from about 33% to about 100%by weight of the drilling fluid. The drilling system may be used todrill into a subterranean formation. The subterranean formation maycomprise a water-swellable shale. The drilling fluid may not be foamed.The betaine shale stabilizer may possess one property selected from thegroup consisting of non-toxic, biodegradable, biocompatible, andcombinations thereof.

FIG. 1 illustrates an example drilling assembly 100 in which a drillingfluid 122 comprising a betaine shale stabilizer as disclosed above isused. It should be noted that while FIG. 1 generally depicts aland-based drilling assembly, those skilled in the art will readilyrecognize that the principles described herein are equally applicable tosubsea drilling operations that employ floating or sea-based platformsand rigs, without departing from the scope of the disclosure.

As illustrated, the drilling assembly 100 may include a drillingplatform 102 that supports a derrick 104 having a traveling block 106for raising and lowering a drill string 108. The drill string 108 mayinclude, but is not limited to, drill pipe and coiled tubing, asgenerally known to those skilled in the art. A kelly 110 may support thedrill string 108 as it is lowered through a rotary table 112. A drillbit 114 may be attached to the distal end of the drill string 108 andmay be driven either by a downhole motor and/or via rotation of thedrill string 108 from the well surface. The drill bit 114 may include,but is not limited to, roller cone bits, PDC bits, natural diamond bits,any hole openers, reamers, coring bits, etc. As the drill bit 114rotates, it may create a wellbore 116 that penetrates varioussubterranean formations 118.

Drilling fluid 122 comprising a betaine shale stabilizer may beprepared. Drilling fluid 122 may be prepared by combining an aqueousbase fluid with a betaine shale stabilizer. The aqueous base fluid andthe betaine shale stabilizer may be mixed in any suitable mixer (11,000rpm), or may be mixed inline using a pump (e.g., pump 120). Pump 120(e.g., a mud pump) may circulate drilling fluid 122 through a feed pipe124 and to the kelly 110, which conveys the drilling fluid 122 downholethrough the interior of the drill string 108 and through one or moreorifices in the drill bit 114. The drilling fluid 122 may then becirculated back to the surface via an annulus 126 defined between thedrill string 108 and the walls of the wellbore 116. At the surface, therecirculated or spent drilling fluid 122 may exit the annulus 126 andmay be conveyed to one or more fluid processing unit(s) 128 via aninterconnecting flow line 130. The fluid processing unit(s) 128 mayinclude, but is not limited to, one or more of a shaker (e.g., shaleshaker), a centrifuge, a hydrocyclone, a separator (including magneticand electrical separators), a desilter, a desander, a separator, afilter (e.g., diatomaceous earth filters), a heat exchanger, and/or anyfluid reclamation equipment. The fluid processing unit(s) 128 mayfurther include one or more sensors, gauges, pumps, compressors, and thelike used store, monitor, regulate, and/or recondition the drillingfluid.

After passing through the fluid processing unit(s) 128, a “cleaned”drilling fluid 122 may be deposited into a nearby retention pit 132(i.e., a mud pit). While illustrated as being arranged at the outlet ofthe wellbore 116 via the annulus 126, those skilled in the art willreadily appreciate that the fluid processing unit(s) 128 may be arrangedat any other location in the drilling assembly 100 to facilitate itsproper function, without departing from the scope of the scope of thedisclosure. One or more of the drilling fluid additives may be added tothe drilling fluid 122 via a mixing hopper 134 communicably coupled toor otherwise in fluid communication with the retention pit 132. Themixing hopper 134 may include, but is not limited to, mixers and relatedmixing equipment known to those skilled in the art. Alternatively, thedrilling fluid additives may be added to the drilling fluid 122 at anyother location in the drilling assembly 100. While FIG. 1 shows only asingle retention pit 132, there could be more than one retention pit132, such as multiple retention pits 132 in series. Moreover, theretention put 132 may be representative of one or more fluid storagefacilities and/or units where the drilling fluid additives may bestored, reconditioned, and/or regulated until added to the drillingfluid 122.

The exemplary drilling fluids disclosed herein may directly orindirectly affect one or more components or pieces of equipmentassociated with the preparation, delivery, recapture, recycling, reuse,and/or disposal of the disclosed drilling fluids. For example, thedisclosed drilling fluids may directly or indirectly affect one or moremixers, related mixing equipment, mud pits, storage facilities or units,composition separators, heat exchangers, sensors, gauges, pumps,compressors, and the like used generate, store, monitor, regulate,and/or recondition the exemplary drilling fluids. The disclosed drillingfluids may also directly or indirectly affect any transport or deliveryequipment used to convey the drilling fluids to a well site or downholesuch as, for example, any transport vessels, conduits, pipelines,trucks, tubulars, and/or pipes used to compositionally move the drillingfluids from one location to another, any pumps, compressors, or motors(e.g., topside or downhole) used to drive the drilling fluids intomotion, any valves or related joints used to regulate the pressure orflow rate of the drilling fluids, and any sensors (i.e., pressure andtemperature), gauges, and/or combinations thereof, and the like. Thedisclosed drilling fluids may also directly or indirectly affect thevarious downhole equipment and tools that may come into contact with thedrilling fluids such as, but not limited to, wellbore casing, wellboreliner, completion string, insert strings, drill string, coiled tubing,slickline, wireline, drill pipe, drill collars, mud motors, downholemotors and/or pumps, cement pumps, surface-mounted motors and/or pumps,centralizers, turbolizers, scratchers, floats (e.g., shoes, collars,valves, etc.), logging tools and related telemetry equipment, actuators(e.g., electromechanical devices, hydromechanical devices, etc.),sliding sleeves, production sleeves, plugs, screens, filters, flowcontrol devices (e.g., inflow control devices, autonomous inflow controldevices, outflow control devices, etc.), couplings (e.g.,electro-hydraulic wet connect, dry connect, inductive coupler, etc.),control lines (e.g., electrical, fiber optic, hydraulic, etc.),surveillance lines, drill bits and reamers, sensors or distributedsensors, downhole heat exchangers, valves and corresponding actuationdevices, tool seals, packers, cement plugs, bridge plugs, and otherwellbore isolation devices, or components, and the like.

EXAMPLES

To facilitate a better understanding of the disclosure, the followingexamples of certain aspects of some embodiments are given. In no wayshould the following examples be read to limit, or define, the entirescope of the embodiments.

Example 1

A bentonite hydration test was performed to evaluate the rheology andfiltration control of neat materials. Three different comparative sampleshale inhibitors, designated Samples 1-3, were prepared using 350 mL offresh water and 30 g of bentonite (a water-swellable shale). Sample 1did not comprise a shale stabilizer and nothing further was added to it.Sample 2 comprised 1 g of glycine betaine HCl shale stabilizer toprovide a loading of 1 lb/bbl. Sample 3 comprised 7 g of glycine betaineHCl shale stabilizer to provide a loading of 7 lb/bbl. Sample 4 was acomparative example and comprised 7 g of an alkyl amine shale stabilizerto provide a loading of 7 lb/bbl. The alkyl amine shale stabilizer isapproximately 32-35% active. Thus, a loading of 7 lb/bbl of the alkylamine shale stabilizer is roughly equivalent to a loading of ˜2.25-2.5lb/bbl of the glycine betaine HCl. The samples were then mixed for 45minutes. After preparation, the rheologies of the three samples weredetermined at room temperature using a Model 35A FANN® Viscometer, inaccordance with the procedure set forth in API RP Practice 13B-1,Recommended Practice for Field Testing of Water-Based Drilling Fluids.The rheology was then measured at room temperature. After testing therheology, the fluid samples aged 30 minutes and the filtration controlwas measured using a static filter press at 100 psi in accordance withthe procedure set forth in API RP Practice 13B-1, Recommended Practicefor Field Testing of Water-Based Drilling Fluids. A barrel is 42 USgallons. The data is presented in Table 1 below.

TABLE 1 Rheology and Filtration Testing Viscometer Readings Sample 1Sample 2 Sample 3 Sample 4 600 75 24 8 67 300 69 19 5 57  6 52 12 3 35 3 52 12 3 35 Yield Point 63 14 2 47 Filtration, mL 10.4 19 295 24

As indicated in Table 1 below, the addition of betaine to the aqueousbentonite mixture resulted in thinner fluids relative to the control.Therefore, the control experienced a greater degree of clay swellinginduced thickening. The same result was shown as compared to the alkylamine shale stabilizer but to a lesser extent. The betaine shalestabilizer also showed a greater degree of collected filtrate, which isa further indication that bentonite clay swelling has been inhibited.

Example 2

The following comparative formulations were carried out to evaluate toevaluate the efficacy of a betaine shale stabilizer in controlling theerosion of shale. The results are indicated in Table 3 below.

The following components were used to create six drilling fluid samples,designated samples 4-9: tap water, caustic soda, pregelatinized starch,carboxymethylcellulose, xanthan gum, barite, and an oxygen scavenger.The specific formulations of each component of the sample drillingfluids are provided in Table 2 below. Sample 4 did not contain a shalestabilizer. Sample 5 contained an alkyl amine shale stabilizer at aloading of 7 lb/bbl. Sample 6 contained a glycine betaine HCl shalestabilizer at a loading of 7 lb/bbl. Sample 7 contained a glycinebetaine HCl shale stabilizer at a loading of 2.25 lb/bbl. Sample 8contained a glycine betaine HCl shale stabilizer at a loading of 2.5lb/bbl. Sample 9 contained a glycine betaine HCl shale stabilizer at aloading of 2.25 lb/bbl, however, the pH of the drilling fluid wasadjusted to 10. The densities of the drilling fluid samples were 10.8lb/bbl. The alkyl amine shale stabilizer is approximately 32-35% active.Thus, a loading of 7 lb/bbl of the alkyl amine shale stabilizer isroughly equivalent to a loading of ˜2.25-2.5 lb/bbl of the glycinebetaine HCl. A barrel is 42 US gallons.

TABLE 2 Sample Formulations Formulation Component Amount (lb.) Mix Time(min.) Tap Water 315 — Caustic Soda 0.2 5 Pregelatinized Starch 4 7Carboxymethylcellulose 2 7 Xanthan Gum 1.25 15 Barite 131 5 OxygenScavenger 0.1 1 Shale Stabilizer As Specified 5

After preparation, 25 g of London clay (a water-swellable shale) wasadded to the drilling fluid samples. The drilling fluid samples werethen hot-rolled at 150° F. for 16 hours. The London clay was thenfiltered from the drilling fluid samples using the mesh used for sizingthe London clay. The London clay was then rinsed carefully with freshwater to remove the barite and any other residual drilling fluidcomponents. The London clay was then dried at 225° F. to evaporate anywater. The final dried London clay was then weighed. The data ispresented in Table 3 below.

TABLE 3 Shale Erosion Results Sample % Shale Recovery Sample 4 (Control)20 Sample 5 (Alkyl Amine 7 lb/bbl) 93 Sample 6 (Glycine Betaine HCl 7lb/bbl) 97 Sample 7 (Glycine Betaine HCl 2.25 lb/bbl) 90 Sample 8(Glycine Betaine HCl 2.5 lb/bbl) 94 Sample 9 (Glycine Betaine HCl 2.25lb/bbl, 90 pH of 10)

Example 2 thus indicates that the betaine shale stabilizer is able tocontrol shale erosion as well as the alkyl amine shale stabilizer. Asmentioned above, the betaine shale stabilizer is also more economicaland also non-toxic, biodegradable, and biocompatible unlike the alkylamine shale stabilizer.

The preceding description provides various examples of the systems andmethods of use disclosed herein which may contain different method stepsand alternative combinations of components. It should be understoodthat, although individual examples may be discussed herein, the presentdisclosure covers all combinations of the disclosed examples, including,without limitation, the different component combinations, method stepcombinations, and properties of the system. It should be understood thatthe compositions and methods are described in terms of “comprising,”“containing,” or “including” various components or steps, thecompositions and methods can also “consist essentially of” or “consistof” the various components and steps. Moreover, the indefinite articles“a” or “an,” as used in the claims, are defined herein to mean one ormore than one of the element that it introduces.

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues even if not explicitly recited. Thus, every point or individualvalue may serve as its own lower or upper limit combined with any otherpoint or individual value or any other lower or upper limit, to recite arange not explicitly recited.

Therefore, the present examples are well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular examples disclosed above are illustrative only, and may bemodified and practiced in different but equivalent manners apparent tothose skilled in the art having the benefit of the teachings herein.Although individual examples are discussed, the disclosure covers allcombinations of all of the examples. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. Also, the terms in the claimshave their plain, ordinary meaning unless otherwise explicitly andclearly defined by the patentee. It is therefore evident that theparticular illustrative examples disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of those examples. If there is any conflict in the usages of aword or term in this specification and one or more patent(s) or otherdocuments that may be incorporated herein by reference, the definitionsthat are consistent with this specification should be adopted.

What is claimed is:
 1. A method for drilling in a subterraneanformation: providing a drilling fluid comprising an aqueous base fluidand a betaine shale stabilizer; placing the drilling fluid into thesubterranean formation; and drilling a wellbore in the subterraneanformation.
 2. The method of claim 1 wherein the drilling fluid comprisesthe betaine shale stabilizer in an amount in a range of about 0.5 lb/bblto about 10 lb/bbl.
 3. The method of claim 1 wherein the drilling fluidcomprises the betaine shale stabilizer in an amount in a range of about2 lb/bbl to about 7 lb/bbl.
 4. The method of claim 1 wherein the betaineshale stabilizer is selected from the group consisting of alkylbetaines, amine functionalized betaines, branched betaines, betainederivatives, and any combination thereof.
 5. The method of claim 1wherein the betaine shale stabilizer is glycine betaine HCl.
 6. Themethod of claim 1 wherein the aqueous base fluid is present in thedrilling fluid in an amount in the range of from about 33% to about 100%by weight of the drilling fluid.
 7. The method of claim 1 wherein thesubterranean formation comprises a water-swellable shale.
 8. The methodof claim 1 wherein the drilling fluid is not foamed.
 9. The method ofclaim 1 wherein the betaine shale stabilizer possesses one propertyselected from the group consisting of non-toxic, biodegradable,biocompatible, and combinations thereof.
 10. A method for drilling in asubterranean formation: preparing a drilling fluid comprising an aqueousbase fluid and a betaine shale stabilizer; circulating the drillingfluid into the subterranean formation, wherein the subterraneanformation comprises a water-swellable shale; drilling a wellbore in thesubterranean formation while circulating the drilling fluid; andcontacting the water-swellable shale with the drilling fluid.
 11. Themethod of claim 10 wherein the drilling fluid comprises the betaineshale stabalizer in an amount in a range of about 0.5 lb/bbl to about 10lb/bbl.
 12. The method of claim 10 wherein the betaine shale stabilizeris selected from the group consisting of alkyl betaines, aminefunctionalized betaines, branched betaines, betaine derivatives, and anycombination thereof.
 13. The method of claim 10 wherein the betaineshale stabilizer is glycine betaine HCl.
 14. The method of claim 10wherein the aqueous base fluid is present in the drilling fluid in anamount in the range of from about 33% to about 100% by weight of thedrilling fluid.
 15. The method of claim 10 wherein the subterraneanformation comprises a water-swellable shale.
 16. The method of claim 10wherein the drilling fluid is not foamed.
 17. The method of claim 10wherein the betaine shale stabilizer possesses one property selectedfrom the group consisting of non-toxic, biodegradable, biocompatible,and combinations thereof.
 18. A drilling system comprising: a drillingfluid comprising an aqueous base fluid and a betaine shale stabilizer; adrilling assembly; a drill string coupled to the drilling assembly; apumping system fluidically coupled to the drill string, wherein thepumping system is capable of pumping the drilling fluid through thedrill string.
 19. The drilling system of claim 18 wherein the drillingfluid comprises the betaine shale stabilizer in an amount in a range ofabout 0.5 lb/bbl to about 10 lb/bbl.
 20. The drilling system of claim 18wherein the betaine shale stabilizer is selected from the groupconsisting of alkyl betaines, amine functionalized betaines, branchedbetaines, betaine derivatives, and any combination thereof.